1. Field of the Invention
This invention relates generally to oilfield well operations and more particularly to an apparatus and method for rotating a portion of a drill sting in a subterranean wellbore.
2. Background of the Invention
In drilling oil and gas wells for the exploration of hydrocarbons, it is sometimes necessary to deviate the well off vertical and in a particular direction. A large proportion of the current drilling activity involves directional drilling, i.e., drilling deviated and horizontal boreholes, to increase the hydrocarbon production and/or to withdraw additional hydrocarbons from the earth""s formations. Modern directional drilling systems generally employ a drill string having a bottom hole assembly (BHA) and a drill bit at the end thereof that is rotated by a drill motor and/or the drill string.
In vertical or near vertical drilling, cuttings produced while drilling are efficiently carried away from the wellbore by the upward velocity of the drilling fluid (commonly known as the xe2x80x9cmudxe2x80x9d or xe2x80x9cdrilling mudxe2x80x9d). However, where there is more deviation in the well, the force of gravity results in the cuttings settling along the bottom side of the wellbore (sometimes referred to as the xe2x80x9clow sidexe2x80x9d). As the cuttings settle, a xe2x80x9cbedxe2x80x9d of solids can form, which can significantly increase the drag forces on the drill string.
Slide-type drill string, or in particular, coiled tubing, involves a pulsating advancement of the drill string in an attempt to constantly overcome the static friction of the drill string on the formation. Drill strings which include jointed pipe as the drill pipe are rotated from the surface to change the static friction to a dynamic friction.
Current coiled tubing drilling applications, involving non-rotating drill strings, are limited by the friction created by the formation of solids in the bottom of the wellbore and the string compressible load capability in achieving the necessary depths of extended reach wellbores or highly deviated wellbores. As a result of the non-rotational setup of coiled tubing applications, the drill string is exposed to enormous amounts of axial frictional forces while sliding the drill string into and out of the wellbore. The horizontal inclinations and curvature in the wellbore increase the likelihood that a non-rotating drill string will become lodged or xe2x80x9cstuckxe2x80x9d in the wellbore, thereby preventing further insertion or extraction of the drill sting.
Drill strings may also become lodged in a wellbore as a result of differential sticking. Differential sticking occurs when the drill string remains at rest against the wellbore wall for a sufficient amount of time to allow filter mud to build up around the drill string. The portion of the drill string that is in contact with the mud is sealed from the hydrostatic pressure of the mud column. The pressure difference between the mud column and the formation pressure of the adjoining formation acts on the area of the drill string in contact with the mud to hold the drill string against the wall of the wellbore. This frictional engagement between the drill string and the mud inhibits or prevents axial and rotational movement of the drill string. However, the kinetic force of a rotating drill string can minimize or deter differential sticking.
Even when a jointed pipe is used as the drill pipe, rotation of the drill pipe from the surface can damage drill pipe around short radius curves and can also damage the borehole at such locations. Continuously rotating the drill string, especially along horizontal or highly deviated sections of the wellbore, can significantly reduce drag, improve hole cleaning, i.e. move cuttings through the borehole and also facilitate tripping of the drill string from the borehole.
U.S. Pat. No. 5,738,178 provides (i) coiled-tubing drill strings wherein the bottom hole assembly can be rotated without rotating the coiled tubing; and (ii) drill pipe drilling systems wherein the drill pipe above the bottom hole assembly can be rotated independent of the bottom hole assembly. However, to drill extended reach horizontal wellbores with coiled tubing drill strings, it is advantageous to rotate at least a portion of the tubing in the horizontal section with and/or without rotating the bottom hole assembly. To drill the wellbore with drill pipe drill strings, it is also advantageous to rotate at least a portion of the drill pipe in the horizontal section without necessarily rotating the remaining drill pipe from the surface.
The present invention provides apparatus and method for rotating a portion of the drill string in the wellbore. By rotating a portion of the drill string, the kinetic force prevents cuttings produced during drilling from settling in the wellbore, thereby significantly reducing the static friction between the rotating portion of the drill string and its surrounding elements and reducing the probability of differential sticking and thus allowing drilling of deeper wellbores by such a drill string compared to a non-rotating drill string. Such a system also facilitates tripping of the drill string from the wellbore.
The present invention provides apparatus and method for rotating a portion of a drill string in the wellbore. The drill string of the present invention comprises upper and lower sections wherein the lower section rotates relative to the upper section of the drill string which extends to the surface. The upper and lower sections of the drill string can comprise coiled tubing, jointed tubing or a combination of coiled and jointed tubing. The lower section of the drill string comprises at least a portion of a bottom hole assembly (BHA), which includes a drill bit and downhole drilling motor. A rotational device is positioned within the drill string in order to rotate the lower section. Upon activation of the rotational device, the lower section of the drill string will be exposed to a continuous rotation. By rotating the lower section of the drill string in the wellbore, static friction forces exhibited by the lower portion are overcome. This reduces the probability of differential sticking of the drill string in the wellbore and can prevent settling of the cuttings on the bottom (low side) of the wellbore, which allows the cuttings to move more freely with the drilling fluid.
An alternative embodiment of the present invention comprises at least one rotational device positioned between the upper and lower sections of the drill string wherein the rotational device allows for passage of wireline and/or fluid.
Another embodiment of the present invention includes at least two spaced apart rotational devices, each such device adapted to independently move a portion of the drill string downhole of the rotational device.
Examples of the more important features of the invention thus have been summarized rather broadly in order that detailed description thereof that follows may better be understood, and in order that the contributions to the art may be appreciated. There are, of course, additional features of the invention that will be described hereinafter and which will form the subject of the claims appended hereto.